Monitoring electrical assets for fault and efficiency correction

ABSTRACT

A system and method of monitoring a plurality of electrical assets comprise an electricity distribution infrastructure, including a plurality of electrical asset sensors coupled to the electrical assets for monitoring an operating condition of the electrical assets as well as any fault conditions. The sensors may include a current transformer for obtaining a current waveform, a GPS receiver for applying a synchronized time-stamp to the waveform data, and a mesh network radio for transmitting the time-stamped waveform data. Data from the plurality of sensors may be encrypted and transmitted over a mesh network to one or more gateways that are in communication with a central command processor. In response to an abnormal operating condition of any electrical asset, the central command processor may determine a probable fault location, a probable fault type, and a fault response.

This application is a Divisional application of U.S. patent applicationSer. No. 11/520,368, filed Sep. 13, 2006 and claims benefit of priorityfrom U.S. Provisional Application No. 60/716,413 filed Sep. 13, 2005,the contents of which are incorporated herein by reference.

TECHNICAL FIELD

The present invention relates generally to monitoring an electricalinfrastructure and, more particularly, to locating and identifyingdisturbances and determining status of electrical assets in anelectrical infrastructure.

BACKGROUND OF THE INVENTION

Based, in part, on the recent deregulation of the electrical supplymarket, increased competition amongst electricity providers has promptedthe need for increased efficiency in electricity distribution as well asincreased quality of service. In the event of a fault condition, forexample, there is a need for rapid determination of the fault locationand fault type so that work crews may be dispatched for rapid responseto a fault or outage. Within dense urban areas, in particular, there isa need for precise power distribution asset monitoring due to the sheernumber of electrical assets (e.g., power lines, transformers, etc.) thatmay be the cause or location of a fault condition, and the concomitantdifficulty in pin-pointing the location of such a fault condition.Generally, fault conditions may arise from such events as lightningstrikes, fallen trees, blown transformers, and strong winds, forexample.

Aside from determining fault locations for rapid-response by work crews,there is also a need to improve the efficiency of electricitydistribution. This may be done by power factor correction and loadmonitoring, for example. In order to achieve desirable levels ofefficiency (e.g., 99% power factor correction), however, utilitiesrequire accurate monitoring of electrical assets in their electricitydistribution infrastructure.

Electrical utilities are responsible for management and control of theelectricity distribution assets and, thus, monitor these assets andcoordinate field personnel in a variety of maintenance andfault-response activities via a central command center. Many suchcentral command centers isolate outage or fault locations based oncustomer complaints and reports of outages. Some utilities alsoimplement sensors for monitoring electrical assets and reporting faultsand/or outages. These existing monitoring systems, however, are unableto pin-point the source of a fault, identify the probable cause of thefault, or identify the chain of events leading to the fault.

A further problem faced by the utilities includes theft and inaccuracyin existing electricity meters, whereby customers are eitherconsistently under-billed or over-billed due to inaccurate usagemetering. Currently, this problem may be addressed by implementing oneor more sensors on power lines leading to a customer, whereby the sensorreadings are compared to electric meter readings. This presents anadditional cost to utilities, however, as they incur overhead associatedwith hiring workers to drive around and collect meter and sensorreadings, making such an implementation undesirably cost-prohibitive.

SUMMARY OF THE INVENTION

The present invention is embodied in an apparatus for monitoring anelectrical asset in an electrical infrastructure. The apparatus mayinclude a sensor coupled to the electrical asset for obtaining datacorresponding to at least one of a voltage, current, and phase anglewaveforms, a globally synchronized timer for time-stamping the data witha globally synchronized time, a mesh network radio for communicating atleast one gateway and for relaying communications between one or moreother electrical asset monitors and the at least one gateway, and apower supply for extracting and storing energy from the electrical assetand supplying power to at least the sensor, the timer, and the radio.

In a further embodiment, such an apparatus may be used in a system formonitoring a plurality of electrical assets that define an electricalinfrastructure. The system may include electrical asset monitors coupledto the electrical assets, one or more gateways having mesh networkradios for communicating with the electrical asset monitors and anetwork interface for communicating with a central command center via anetwork distinct from the mesh network, and a central command center.The central command center may include a network interface forcommunicating with the one or more gateways, a memory for storing adatabase of fault signatures, a second memory for storing the senseddata, and a processor for analyzing the sensed data to identify aprobable fault type, a probable fault location, and a fault response. Inthe further embodiment, the system further includes a mesh network forrouting communications among the electrical asset monitors and the oneor more gateways, whereby the mesh network coordinates efficientcommunication paths among the plurality of electrical asset monitors andthe one or more gateways.

In an alternate embodiment of the present invention, a method ofmonitoring an electrical asset in an electrical infrastructure mayinclude sensing, by a monitoring element, one or more of a current,voltage, and phase angle waveforms of an electrical asset, digitizingthe sensed waveforms into a digital signal, encrypting the digitalsignal. The encrypted, digital signal may then be transmitted through amesh network, where it is routed to a gateway based on a most efficientpath between the monitoring element and the gateway. The method mayfurther include relaying, to a gateway, one or more other encrypteddigital signals from other monitoring elements.

In a further alternate embodiment, a method of managing electricalassets that define an electrical infrastructure may be performed byreceiving, from one or more gateways, encrypted data collected by aplurality of electrical asset sensors, decrypting the encrypted data toobtain a plurality of sensed waveforms, wherein each one of the sensedwaveforms is synchronized according to a globally synchronized timer andincludes a plurality of coordinates identifying a source location of thewaveform, and determining, based on the plurality of sensed waveformsand respective source locations, one or more of an abnormal conditionand a normal condition.

It is to be understood that both the foregoing general description andthe following detailed description are exemplary, but are notrestrictive, of the invention.

BRIEF DESCRIPTION OF THE DRAWING

The invention is best understood from the following detailed descriptionwhen read in connection with the accompanying drawing. It is emphasizedthat, according to common practice, the various features of the drawingare not to scale. On the contrary, the dimensions of the variousfeatures are arbitrarily expanded or reduced for clarity. Included inthe drawing are the following figures:

FIG. 1 is a block diagram illustrating an electrical asset monitoringdevice coupled to an electric power line, according to one embodiment ofthe present invention;

FIG. 2 is an exemplary diagram of an electrical asset monitoring devicecoupled to an electric power line, further illustrating exemplarycircuit components of the electrical asset monitoring device, accordingto an alternate embodiment of the present invention;

FIG. 3 is an exemplary diagram of a plurality of electrical assetmonitoring devices coupled to electric power lines for monitoring thepower lines and transmitting information to a gateway, according to oneembodiment of the present invention;

FIG. 4 is a schematic diagram illustrating a plurality of electricalasset monitoring devices on a power line for use in describing anexemplary process of fault location;

FIG. 5 is a schematic diagram of an exemplary mesh network formonitoring a plurality of electrical assets, according to the presentinvention;

FIG. 6 is a flow-chart illustrating a method of monitoring an electricalasset, according to the present invention; and

FIG. 7 is a flow-chart illustrating a method of managing an electricalasset monitoring system, according to the present invention.

DETAILED DESCRIPTION OF THE INVENTION

The present invention is embodied in an apparatus, system, and method ofmonitoring a plurality of electrical assets that comprise an electricitydistribution infrastructure. The electric assets being monitored mayinclude power lines, cables, circuit breakers, switches, andtransformers, for example. Monitoring activities are overseen by acentral command center that obtains sensor data from multiple gateways.Each gateway collects data from a plurality of remotely located sensorsthat are coupled to respective ones of the electrical assets forobtaining data on the operating condition of the electrical assets. Datafrom any given sensor is routed to a gateway via a mesh network, wherethe data is multi-hopped from sensor-to-sensor according to an efficientcommunication path to the gateway. The gateway then re-routes the datafrom the mesh network, which is a tier-2 network, to the central commandcenter via a tier-1 network (e.g., radio link, fiber optic link, theInternet, a leased common-carrier link, etc.). Based on the aggregatedata from the multiple sensors, the central command center may monitorthe electrical assets to identify normal operating conditions, abnormaloperating conditions, faults, probable fault types, probable faultlocations, electric metering errors, and power system inefficiencies(e.g., for power factor correction), for example.

Referring now to the drawing, in which like reference numbers refer tolike elements throughout the various figures that comprise the drawing,FIG. 1 is a block diagram illustrating one embodiment of the presentinvention. Electrical asset monitoring device 100 is shown as beingcoupled to an exemplary electrical asset (e.g., a power line) 110, via amechanical clamping mechanism or any other means known to those ofordinary skill in the art. Electrical asset monitoring device 100includes a power supply 101 for extracting and storing energy from theelectrical asset 110 in order to supply operating power to device 100.Power supply 101 may be coupled to electrical asset 110 via a directelectrical coupling, an inductive coupling, a capacitive coupling, or byany other means known to those of ordinary skill in the art. Powersupply 101 is also electrically coupled (not shown in FIG. 1) tocomponents 102-107 of monitoring device 100.

Sensor 102 obtains data corresponding to operating conditions ofelectrical asset 110. The data obtained by sensor 102 may comprise avoltage waveform, a current waveform, or a phase signal of electricitybeing transmitting by electrical asset 110. Alternately, sensor 102 mayobtain data corresponding to a current waveform, a separate sensor (notshown in FIG. 1) may obtain data corresponding to a voltage waveform,and on-board processor 105 may calculate the phase waveform. The phasewaveform may be a phase difference between the voltage and currentwaveforms over time, for example. Alternately, the phase waveformcalculation may be performed by an off-board central processor (notshown in FIG. 1). Other measurements that may be gathered by sensor 102include a temperature and/or frequency of electrical asset 100. Sensor102 may be either an analog or a digital sensor. If sensor 102 is ananalog sensor, however, either processor 105 or a separateanalog-to-digital converter (not shown in FIG. 1) may digitize theanalog data from sensor 102.

It may also be desirable to ensure that voltage and/or current waveformsare synchronized to data being collected by other monitoring devices(not shown in FIG. 1) for other electrical assets (not shown in FIG. 1).Accordingly, globally synchronized timer 104 is provided to obtain atiming signal that is synchronized with the other monitoring devices.Globally synchronized timer 104 may include a global positioning system(GPS) receiver that receives a globally synchronized time as well as alocal timer that is tuned to the GPS timing signal. Accordingly, in theevent that the GPS receiver is not able to find a GPS signal, the localtimer is able to provide a substantially synchronized timing signaluntil it is able to re-synchronize with the GPS signal. The GPS receiverof globally synchronized timer 104 may also be used to obtain aplurality of coordinates corresponding to the location of monitoringdevice 100.

Data obtained by sensor 102, therefore, may be time-stamped by on-boardprocessor 105 with the timing signal obtained from globally synchronizedtimer 104 (i.e., either from a GPS receiver or a local timer synched tothe GPS receiver). The time-stamped data may then be transmitted to agateway (not shown in FIG. 1) from monitoring device 100 via meshnetwork radio 103. Mesh network radio 103 may also receivecommunications from other monitoring devices (not shown in FIG. 1)requesting that their respective data be relayed to a gateway (not shownin FIG. 1). Accordingly, mesh network radio 103 relays suchcommunications according to efficient communication paths.

Mesh network radio 103 may be configured to operate using a Zigbeeprotocol, a Wi-Fi protocol, Wi-Max protocol or any other mesh networkconfiguration capable of self-configuration and dynamic load-balancing,whereby efficient communication paths among network participants (i.e.,monitoring devices and gateways) are automatically determined among theparticipants. Alternately, static, predetermined communication paths maybe obtained and programmed into mesh network radio 103, whereby meshnetwork 103 relays communications according to the predetermined paths.Further, if a Zigbee protocol is being used, it may be desirable toboost the output power of mesh network radio 103 to 1 watt (i.e., bothreceiver and transmitter), thereby increasing the communications rangeof monitoring device 100. In addition, the data transmitted by the radio103 may include an error correction code (ECC) to make the transmissionmore robust. Monitoring device 100 may also include memory 107 forstoring the time-stamped data, if desired.

In a further embodiment, processor 105 may detect an abnormal operatingcondition of electrical asset 110 based on the data collected by sensor102. This may be done, for example, by comparing sensed data with eithera predetermined threshold, or an operating point, which may be a movingaverage of the sensed data. Accordingly, mesh network radio 103 may beconfigured to transmit sensed data only when an abnormal operatingcondition is detected by processor 105. Alternately, sensed datacorresponding to all conditions of electrical asset 110—including bothabnormal and normal conditions—may be transmitted by mesh network radio103.

In yet another embodiment, monitoring device 100 may include memory 106for storing a plurality of fault signatures corresponding to a number ofdifferent fault types (e.g., lightning strike, downed wire, line-to-linefault, etc.). Fault signatures stored by memory 106 may be any number ofexemplary fault signals developed to mimic real fault conditions and areavailable for licensing from various institutions, such as Texas A&MUniversity, for example. According to the present embodiment of theinvention, on-board processor 105 may correlate data corresponding to anabnormal condition of electrical asset 110 to the plurality of faultsignatures stored by memory 106. Based on the correlation, processor 105may be able to identify a probable fault type corresponding to theabnormal condition. Accordingly, the fault type identifying the abnormalcondition, the time-stamped data corresponding to the abnormalcondition, and the plurality of GPS coordinates corresponding to thelocation of monitoring device 100 (which, in one embodiment of theinvention, may be considered to be a probable fault location) may betransmitted by mesh network radio 103.

In an additional embodiment, any number of encryption schemes known tothose of ordinary skill in the art may be implemented for encryptingcommunications to and/or from mesh network radio 103. For example,encryption may be performed according to the advanced encryptionstandard (AES), the data encryption standard (DES), Triple DES,Blowfish, or Twofish algorithms, where the encryption key may beobtained via tree-group Diffie-Hellman (TGDH), the RSA protocol, or anelliptic-curve cryptography protocol. Accordingly, processor 105 mayencrypt data that is transmitted by mesh network radio 103, includingthe fault location, the fault type, and time-stamped data correspondingto the fault. In an embodiment where data corresponding to normaloperating conditions are also transmitted, data corresponding to normalconditions may also be encrypted according to a desirable encryptionscheme prior to being transmitted by mesh network radio 103.

According to a further embodiment of the invention, FIG. 2 illustratesan exemplary monitoring device 200 that may be coupled to power line202. Exemplary monitoring device 200 includes current transformer 201inductively coupled to power line 202 for providing a stepped-downcurrent signal for current sensing and/or providing operating power.Current transformer 201 steps down the current supplied by electricalasset 202 by a predetermined ratio to provide a current signal that iswithin an operating range of analog-to-digital converter 203. Beforereaching analog-to-digital converter 203, the current signal may also befiltered by a conditioning circuit (e.g. a low-pass filter) (not shownin FIG. 2) to remove high frequency noise from the current signal.Resistors 220, 221, and 222 comprise a voltage divider for providing adesirably scaled signal to analog-to-digital converter 203. Power supply210 (shown in phantom) includes high potential node 211 (for providingan operating voltage, e.g. V_(cc)), common potential node 212 (forproviding a reference potential, e.g. ground), voltage regulator 215 (tomaintain a constant operating voltage), energy storage capacitor 214(for providing operating power in the case of an outage on theelectrical asset being monitored), and Zener diode 213 (for voltageregulation and transient protection across capacitor 214). As shown inFIG. 2, current transformer 201 is a split-core transformer coupled,inductively, to power line 202. Those skilled in the art will recognizethat any other current transformers may be used, such as a closed-corecurrent transformer, for example. Alternative embodiments of theinvention may use a potential transformer, a Hall effect sensor, aRogowski coil, or an optoelectronic sensor including, for example, aKerr cell, a Pockels cell and/or a Faraday-effect sensor for sensingvoltage and/or current waveforms of electric power line 202. Theexemplary monitoring device 200 may include protection circuitry, inaddition to the Zener diode 213, to shield the device 200 from transientvoltage and current spikes which may occur, for example, during alightning strike.

Digitized data from analog-to-digital converter 203 is time-stamped byprocessor 204 with a timing signal provided by timing module 206. Timingmodule 206 may include a local timer synched to a timing signal providedby a GPS receiver, as described above. This GPS receiver may alsoprovide coordinates identifying the location of monitoring device 200.Alternatively or in addition, the device 200 may have an identifier bywhich its position is known to the central command center and thisidentifier may be transmitted to the command center. If both theidentifier and the GPS coordinates are sent, the command center may beable to determine if the device 200 has moved from its assignedlocation. Processor 204 may perform other functions, such as encryptingthe time-stamped data, for example. In one embodiment of the invention,processor 204 may be a digital signal processor (DSP), capable ofsampling data from sensor 201 128 times per 60 Hz power cycle, forexample. Processor 204 may also detect an abnormal condition of powerline 202 by comparing the time-stamped data to an operating point ofpower line 202, which may be a moving average of sensed data or apredetermined threshold, for example. Processor 204 is also coupled to anon-volatile memory (not shown) which stores the digitized andtime-stamped data. If, due to a loss of power, this data cannot betransmitted proximate in time to the occurrence of the fault, it may bestored in the non-volatile memory and transmitted when power isrestored.

Digitized, time-stamped data from processor 204 may then be transmittedby mesh network radio 205. If provided, GPS coordinates and/or anidentifier, identifying the location of monitoring device 200 may alsobe included with mesh network radio 205 transmissions. Mesh networkradio 205 is configured to transmit and relay messages to one or moregateways according to dynamically calculated efficient communicationpaths, and may be a Zigbee radio, a Wi-Max radio or a Wi-Fi radio. Ifradio 205 is a Wi-Fi radio, it may be programmed to operate in ad-hocmode, where the efficient communication paths are coordinated by anad-hoc on-demand distance vector (AODV) algorithm.

FIG. 3 illustrates an electrical infrastructure monitoring system inwhich exemplary electrical asset monitors 301, 302, and 303, such as themonitoring devices described above, may be implemented for monitoringelectric lines 311, 312, and 313, respectively, in electricitydistribution infrastructure 300. Electrical asset monitors 321, 322, and323 may be used for monitoring electric asset 320. Monitors 301-303 and321-323 are coupled to electric lines 311-313 and electric asset 320,respectively, and each includes a sensor for obtaining voltage, current,and/or phase waveforms from the electric line. Each of monitors 301-303and 321-323 also includes a mesh network radio for transmitting andrelaying communications to gateway 310, a globally synchronized timerfor time-stamping data obtained by the sensor, and a power supplycoupled to the electric line for obtaining operating energy from theelectric line. Monitors 301-303 and 321-323 may also include a powerstorage device for at least temporarily providing operating power in theevent of a power outage.

In one embodiment of the invention, gateway 310 is one of a plurality ofgateways configured to receive communications from a plurality ofmonitoring devices including, among others (not shown in FIG. 3),monitors 301-303 and 321-323. Accordingly, gateway 310 may include amesh network radio for receiving communications via a mesh network inwhich the plurality of monitoring devices and gateways may beparticipants. Gateway 310 may also include a network interface forrelaying communications received from the monitoring devices via themesh network to a central command center via a network distinct from themesh network.

In one embodiment of the invention, gateway 310 may receivecommunications from monitors 301-303 and 321-323 via the mesh networkand re-transmit those communications via the network interface, whichmay be, for example, a modem configured for communication with thecentral command center over a global information network (e.g. theInternet). In an alternate embodiment, the network interface may be amodem configured to broadcast the communication over an existing radiochannel used by an electric utility company in charge of electricitydistribution infrastructure 300. In another alternate embodiment, thenetwork interface may be a light-emitting diode or a laser forcommunicating over an optical fiber. In yet another alternateembodiment, the network interface may be a modem configured forcommunication across a leased common-carrier link.

In a further embodiment of the invention, communications from monitors301-303 and 321-323 may be encrypted according to an encryption scheme,which may include AES, DES, triple DES, Blowfish, or Twofish forencrypting communications using a private key obtained via TGDH, an RSAprotocol, or an elliptic-curve cryptography protocol, for example.Accordingly, monitors 301-303 and 321-323 may include a processorconfigured to implement the encryption scheme and encrypt communicationsto gateway 310. Gateway 310 may also include a processor configured toimplement the encryption scheme and decrypt communications from monitors301-303 and 321-323. Gateway 310 may also be configured to implement asecond encryption scheme for encrypting communications to the centralcommand center. The second encryption scheme may either be the same asor different from the first encryption scheme. In the presentembodiment, the central command center (not shown in FIG. 3) isconfigured to implement the second encryption scheme for decryptingcommunications from gateway 310 and any other gateways in the system(not shown in FIG. 3).

The central command center (not shown in FIG. 3) is operated by anelectric utility company, or any other entity that manages and monitorsthe electricity distribution infrastructure, and may include a networkinterface for communicating with gateway 310 and the other gateways inthe system. The command center also includes a memory for storing adatabase of fault signatures, a second memory for storing sensor dataoriginating from monitors 301-303, 321-323, and any other monitoringdevices in the system, and a processor for analyzing the sensor data inorder to identify a fault, a probable fault type, a probable faultlocation, and a fault response.

The central command center may identify a fault by comparing sensor datafor electrical assets being monitored to expected operating point(s) forthose electrical assets. Accordingly, if the sensor data indicates thatan electrical asset is operating at a certain percentage above or belowthe operating point, then the central command center may determine thatthe electrical asset has a fault. The operating point for eachelectrical asset may be obtained, for example, by taking a movingaverage of sensor data for the electrical asset when it is operating ina normal condition. If a fault is identified at any of the electricalassets, the probable fault type of the fault may be determined bycorrelating the sensor data to a number of fault signatures in thedatabase of fault signatures. The fault signatures correspond to anumber of different fault types (e.g., lightning strike, downed wire,line-to-line fault, etc.), and are exemplary fault signals developed tomimic real fault conditions. Databases of fault signatures may beavailable for licensing from various institutions, such as Texas A&MUniversity, for example.

If multiple monitoring devices located physically close to one another(e.g., within a 1 mile radius) all transmit sensor data identifying afault, then an assumption may be made that the monitoring devices haveidentified the same fault. Accordingly, sensor data from each ofmonitoring devices may be correlated to the fault signatures in order toidentify the probable fault type. Alternately, a weighted average ofcorrelation values may be calculated, with the fault signaturecorrelation value for a monitoring device that detected the fault firstbeing given a highest weight and the fault signature correlation valuefor a monitoring device that detected the fault last being given alowest weight.

For example, five monitoring devices, M1-M5, may detect the fault, withM1 detecting the fault first, M2 detecting the fault second, M3detecting the fault third, M4 detecting the fault fourth, and M5detecting the fault last. Accordingly, for any given fault signature inthe fault database, correlation values C₁-C₅ are obtained by correlatingsensor data from each of M1-M5, respectively. A final correlation value,C_(final), for the detected fault may be obtained, therefore, byobtaining a weighted average of C₁-C₅ based on the sequence in whichM1-M5 detected the fault. The final correlation value is obtainedaccording to any predetermined weighting scheme, which, for the presentexample, may be:

${C_{final} = \frac{{w_{1} \cdot C_{1}} + {w_{2} \cdot C_{2}} + {w_{3} \cdot C_{3}} + {w_{4} \cdot C_{4}} + {w_{5} \cdot C_{5}}}{w_{1} + w_{2} + w_{3} + w_{4} + w_{5}}},$where w₁-w₅ are the predetermined weighting values. A fault typecorresponding to the fault signature with the highest final correlationvalue may be designated as the probable fault type.

The central processor may also analyze data from the monitors in orderto identify the probable fault location. FIG. 4 illustrates an exemplaryelectricity distribution infrastructure 400 employing monitors s1-s7 formonitoring electrical lines 411-416. Each of electrical lines 411-416may have differing characteristics, including, for example, apropagation velocity. Accordingly, the central command center may alsoinclude a memory for storing a database of electrical asset (i.e.,electrical lines in the present embodiment) characteristics including,for example, propagation velocities. In the present exemplaryinfrastructure 400, therefore, electrical lines 411, 413, and 416 mayhave propagation velocity v1, line 412 may have propagation velocity v2,and lines 414 and 415 may have propagation velocity v3. An abnormalcondition on at least line 411 may arise at time, t0, due to fault 401at fault location 410. Fault 401 also causes fault waveforms 402 and403, with fault waveform 402 traveling toward monitor s1 and faultwaveform 403 traveling toward monitor s7. Monitor s7 detects faultwaveform 403 at time t7 and monitor 51 detects fault waveform 402 attime t1.

Accordingly, monitors s1 and s7 sense and record data corresponding tofault waveforms 402 and 403, respectively. The data corresponding tofault waveforms 402 and 403 are also time-stamped with times t1 and t7,respectively, where times t1 and t7 are obtained according to a globallysynchronized timer. The globally synchronized timer may obtain theglobally synchronized time from a GPS receiver, for example, where theremay be desirably negligible timing error between monitors s1-s7. Forexample, at time, t1, sensor s1 time-stamps sensed data with t1 and notwith some erroneous time, t1+error1. A GPS receiver may also be able toprovide monitors s1-s7 with GPS coordinates identifying a globallocation of sensors s1-s7. Monitors s1 and s7 may transmit, to thecentral command center, the time-stamped data corresponding to faultwaveforms 402 and 403, as well as the GPS coordinates that identifytheir respective global locations.

The central command center may then determine a probable location offault 401 by analyzing the data to determine the distance ds7 of faultlocation 410 from monitor s7, and distance ds1 of fault location 410from monitor s1. The central command center may then perform thefollowing exemplary calculation procedure to identify the probable faultlocation.

The procedure begins by setting ds1=v1·(t1−t0), where ds1 is an unknowndistance between monitor s1 and fault location 410, v1 is a knownpropagation velocity of line 411, t1 is a known time at which faultwaveform 402 is detected, and t0 is an unknown time at which fault 401occurs. Solving for t0, above, t0=t1−ds1/v1. Similarly, ds7=v1·(t7−t0),where ds7 is an unknown distance between monitor s7 and fault location410, v1 is a known propagation velocity of line 411, t7 is a known timeat which fault waveform 403 is detected, and t0 is an unknown time atwhich fault 401 occurs. The distance between monitors s1 and s7, d11,may be stored in a database, or may be calculated according to the GPScoordinates identifying the global position of monitors s1 and s7. It isalso known that d11=ds1+ds7. The equations obtained, above, may besubstituted for ds1 and ds7 to obtain: d11=v1·(t1−t0)+v1·(t7−t0), whichsimplifies to d11=v1·(t1+t7−2·t0). Substituting for t0,d11=v1·(t1+t7−2·(t1−ds1/v1)), which simplifies to d11=v1·t7−v1·t1+2·ds1,where d11, v1, t7, and t1 are known values. Accordingly, the centralcommand center may solve for ds1 and ds7, thereby identifying theprobable fault location. Those of ordinary skill in the art will be ableto perform similar calculations to identify probable fault locations forfaults originating on any of lines 411-416.

A fault response may be assigned and initiated once the central commandcenter has identified identify a fault, a probable fault type, and aprobable fault location. In one embodiment, the fault response may be awarning that includes the probable fault location and the probable faulttype. The fault warning may be, for example, a fax message, an e-mailmessage, a pager message, an audiovisual warning, a network alert, anSMS message, and/or a Simple Object Access Protocol (SOAP) message. Ifan unbalanced power factor is detected, the central command center mayinitiate a power factor correction algorithm, which may include, forexample, switching on any number of capacitor banks, or any other powerfactor correction method known by those of ordinary skill in the art. Ifan electrical asset failure (e.g., blown transformer, downed wire, etc.)is detected, then the fault response may be to initiate an electricalasset isolation algorithm. Such an algorithm may switch the faultedelectrical asset out of the electricity distribution infrastructure,thereby preventing the possible spread of the fault condition to otherelectrical assets. If an electrical asset overload is detected, then thefault response may be to initiate an electrical asset bypass algorithm.Such an algorithm may direct electricity distribution around theoverloaded asset, or switch in additional electrical assets into theelectricity distribution infrastructure, thereby preventing a fault fromoccurring at the overloaded asset. Alternately, the electrical assetbypass algorithm may control the source of the overloading in order toreduce the load on the electrical asset. For example, if the source ofoverloading includes an air conditioning system of a large officebuilding, then the algorithm may have control over the thermostat of thelarge office building in order to reduce the load in peak conditions.

Referring, again, to FIG. 3, monitors 321-323 may be used to monitorelectricity consumption of substation 320, which may be a residentialdistribution station, for example. In one embodiment, substation 320 mayinclude one or more electric meters for logging electricity consumption.According to the prior art, electric utility personnel drive to, andmanually interrogate the electric meters in order to obtain the loggedelectricity consumption data. In order to eliminate the need for manualinterrogation of the electric meters, one embodiment of the presentinvention includes electric meters that are configured to transmit thelogged electricity consumption data to the central command center viathe mesh network. Electric meters in the present embodiment may includea mesh network radio for communicating via the mesh network and aglobally synchronized timer for time-stamping the consumption data.Accordingly, the central command center may receive time-stampedobserved consumption data from the electric meters as well astime-stamped actual consumption data from monitors 321-323. The commandcenter may then compare the observed and actual consumption values overtime in order to determine whether an error exists at any of theelectric meters. A theft monitor may be alerted, when the magnitude ofany such error exceeds some predetermined threshold. For example, if anelectric meter indicates that consumption is some percentage below anactual consumption value (e.g., 50% of actual consumption), then anassumption may be made that someone has altered the electric meter inorder to steal electricity. Accordingly, the theft monitor may assign aninvestigator to investigate the assumed theft, generate a bill based onthe actual consumption value, or assign a repair crew to repair theelectric timer.

FIG. 5 illustrates an exemplary mesh network 500 formed according to oneembodiment of the present invention and including gateways 501-505 andelectric asset monitors 510-535. A plurality of direct communicationlinks are shown as formed between monitors and between certain monitorsand gateways. The mesh network coordinates efficient communication pathsamong the electrical asset monitors and the one or more gateways. Forexample, electrical asset monitor 531 may transmit data to gateway 501according to efficient path 550, whereby communications are routedthrough electrical asset monitor 524 to monitor 518, monitor 518 tomonitor 515, and monitor 515 to gateway 501. In the event of a failureof one or more of the monitors, however, the most efficient path to agateway may not necessarily be the shortest path. The mesh network,therefore, dynamically determines efficient paths. A failure of themonitors may arise from a power outage that results in one or moremonitors dropping out of the network. Alternately, the failure may arisefrom one or more monitors being congested with network traffic, causingan undesirable slowing of communications to and from the congestedmonitors. In the event of a failure of monitor 518, monitor 515, and/ormonitor 524, for example, monitor 531 may transmit data according toalternate efficient path 555. Alternate efficient path 555 may routedata from monitor 531 through monitor 532 to monitor 525, monitor 525 tomonitor 520, monitor 520 to monitor 511, and monitor 511 to gateway 503.

In one embodiment of the invention, the mesh network may be configuredaccording to the ZigBee protocol. In an alternate embodiment, the meshnetwork may be configured according to an ad-hoc Wi-Fi protocol, whereefficient communication paths are determined and coordinated accordingto an ad-hoc on-demand distance vector (AODV) algorithm, as known bythose of ordinary skill in the art.

Referring now to FIG. 6, a flow-chart is shown for an exemplary processfor monitoring an electrical asset in an electrical infrastructure. Theprocess may be implemented by the exemplary electrical asset monitoringdevices, described above, for example. As shown in FIG. 6, the processmay begin with step 601 by obtaining data from an analog sensor (i.e.,the monitoring element) corresponding to a current waveform, a voltagewaveform, and/or a phase waveform of the electrical asset beingmonitored. Step 602 then digitizes the analog data (i.e., the sensedwaveform(s)) into a digital signal. Optional step 603 may then encryptthe digital signal according to an encryption scheme, as describedabove. Step 604 may transmit the optionally encrypted digital signalthrough a mesh network, where the transmission is routed to a gatewaybased on a most efficient path. A further step (not shown in FIG. 6) maybe performed in parallel with steps 601-604 and may include relaying,according to a most efficient path, other encrypted digital signals fromother monitoring elements, where the other monitoring elements aremonitoring other electrical assets. In a further embodiment, the processmay also include the step of extracting and storing operational powerfrom the electrical asset being monitored.

In yet a further embodiment, the process may also include the step ofreceiving a globally synchronized time for synching a local timer and aplurality of coordinates corresponding to a position of the monitoringelement. Once the globally synchronized time is received, the processmay then time-stamp the sensed waveforms according to the local timer.In the present embodiment, the process may also encrypt the plurality ofcoordinates corresponding to the position of the monitoring element, andtransmit the encrypted coordinates along with the time-stamped,encrypted waveform data. As described above, the device mayalternatively or in addition transmit an identifier by which itsposition is known to the command center.

FIG. 7 is a flow-chart illustrating a process according to yet anotherembodiment of the present invention. The process is for managing one ormore electrical assets that define an electrical infrastructure, such asa power grid, for example. The process may begin with step 701, whichreceives, from one or more gateways, encrypted data corresponding to oneor more of a current, a voltage, and/or a phase angle waveform sensed bya plurality of electrical asset monitors in the electricalinfrastructure. Each one of the electrical asset monitors in theelectrical infrastructure may be coupled to an electrical asset (e.g., apower line) to monitor an operating condition of the electrical asset.Step 702 may then decrypt the encrypted data to obtain the sensedwaveform(s), where the waveforms are synchronized according to aglobally synchronized timer and may further include a plurality ofcoordinates identifying a source location of each waveform. Thecoordinates may be GPS coordinates, for example or coordinates providedby a central database based on a received identifier. In one embodiment,the decryption may be performed according to the advanced encryptionstandard (AES). Step 703 may then determine, based on the plurality ofsensed waveforms and respective source locations, operating conditionsfor each of the electrical assets being managed. The operating conditionfor an electrical asset may be compared to an expected value (i.e., anoperating point, which may be obtained, for example, by taking a movingaverage of the operating condition of a given electrical asset) in orderto determine whether the electrical asset is operating under a normalcondition or an abnormal condition.

If, in step 702 an abnormal condition is detected, step 704 calculates aprobable fault type and a probable fault location of a fault that may becausing the abnormal condition. The calculations may be performed basedon the sensed waveform data and the source locations of any number ofelectrical asset monitors that sensed the abnormal condition, inaddition to a database having a number of electrical assetparameters/characteristics. The electrical asset parameters database mayinclude, for example, a propagation velocity of the electrical asset,which may be used to calculate the probable fault location as describedabove with reference to FIG. 4. The probable fault type may bedetermined by correlating the sensed waveform with a database of faultsignatures, where a fault signature that has the highest correlationwith the sensed waveform corresponds to the probable fault type. Ifmultiple monitors detected the fault, then there may be multiple sensedwaveforms that correspond to the fault and, accordingly, the probablefault type may be based on a weighted average of the correlations ofeach sensed waveform to the fault signature database, as describedabove.

Step 705 may then assign a fault response based on the probable faulttype and the probable fault location. In one embodiment, step 705 mayassign a fault warning for a momentary fault, a temporary fault, or anincipient fault. This may include, for example, generating a SOAPmessage having the probable fault type and probable fault location andtransmitting the SOAP message according to a SOAP notificationinterface. In another embodiment of the invention, step 705 may assign apower factor correction algorithm when the probable fault type is anunbalance power factor fault. The power factor correction algorithm mayinclude, for example, engaging any number of capacitor banks or otherreactive elements. In yet another embodiment, step 705 may assign anelectrical asset isolation algorithm when the probable fault type is anelectrical asset failure fault. The isolation algorithm may include, forexample, opening any number of switches around the electrical asset inorder to isolate the fault from spreading throughout the electricalinfrastructure. In yet another embodiment, step 705 may assign anelectrical asset bypass algorithm when the probable fault type is anelectrical asset overload fault. The bypass algorithm may include, forexample, opening or closing any number of switches around the electricalasset, thereby allowing other electrical assets to pick up some portionof the load on the overloaded electrical asset. Alternately, any numberof devices that may be causing the overload fault (e.g., factories,large office building climate control, etc.) may be controlled to lowerthe load (e.g., affecting the thermostat for a large office building).

If, in step 703, a normal operating condition of the electrical asset isdetected, the process may either terminate (not shown in FIG. 7),restart at step 701 (not shown in FIG. 7), or move to step 710, whichdetermines whether any measured metering data was received for theelectrical asset. If metering data was not received, the process mayeither terminate (not shown in FIG. 7) or restart at step 701. Ifmetering data was received, however, the process may proceed to step711, which calculates, based on the sensed waveform data, actualmetering data for an electric meter that originated the measuredmetering data. Though not shown in FIG. 7, the process may thendetermine, based on the actual metering data and/or the measuredmetering data, a time of use bill for each one of a number of electricmeters. Alternately, step 712 may compare the calculated, actualmetering data and the measured metering data to determine whether anerror exists at any of the electric meters. Step 712 may also determinethe magnitude of any determined error. Step 713 may determine whetherthe magnitude of the error is greater than some threshold. If it is not,the process may either terminate (not shown in FIG. 7) or restart atstep 701. If the error is greater than the threshold, then step 714 mayalert a theft monitor, which may then investigate the error, send arepair crew to fix the error, or generate a bill based on the actualmetering data.

Although illustrated and described above with reference to certainspecific embodiments, the present invention is nevertheless not intendedto be limited to the details shown. Rather, various modifications may bemade in the details within the scope and range of equivalents of theclaims and without departing from the invention.

What is claimed is:
 1. A system for monitoring a plurality of electricalassets defining an electrical infrastructure, the system comprising: aplurality of electrical asset monitors coupled to respective ones of theelectrical assets, each monitor including a sensor coupled to theelectrical asset for obtaining data corresponding to at least one of avoltage, current, and phase angle waveforms, a globally synchronizedtimer, a mesh network radio, a power supply, and a power storage device;one or more gateways, each gateway including a gateway mesh networkradio for communicating with the plurality of electrical asset monitorsand a network interface for communicating with a central command centervia a network distinct from the mesh network; the central command centerincluding a further network interface for communicating with the one ormore gateways, a memory for storing a database of fault signatures, asecond memory for storing the obtained data, and a processor foranalyzing the obtained data to identify a probable fault type, aprobable fault location, and a fault response; and a mesh network forrouting communications among the plurality of electrical asset monitorsand the one or more gateways, whereby the mesh network coordinatesefficient communication paths among the plurality of electrical assetmonitors and the one or more gateways.
 2. The system of claim 1, whereineach one of the plurality of electrical asset monitors include aprocessor configured to implement an encryption scheme to encrypt thedata before it is communicated by the mesh network radio.
 3. The systemof claim 2, wherein each one of the one or more gateways includes aprocessor configured to implement the encryption scheme to decrypt thedata from the plurality of electrical asset monitors and to encrypt thedata according to a further encryption scheme before it is communicatedby the network interface.
 4. The system of claim 2, wherein: theencryption scheme is one of a tree group Diffie-Hellman protocol, an RSAprotocol, and an elliptic-curve cryptography protocol; the encryptionprocessor is configured to encrypt communications with the one or moregateways according to an advanced encryption standard (AES), dataencryption standard (DES), Blowfish, Twofish, or triple DES; and thecentral command center processor is configured to decrypt communicationsoriginating from the plurality of electrical asset monitors.
 5. Thesystem of claim 1, wherein the mesh network is configured according to aZigBee protocol.
 6. The system of claim 1, wherein the mesh network isconfigured according to an ad-hoc Wi-Fi protocol and efficientcommunication paths are coordinated according to an ad-hoc on-demanddistance vector (AODV) algorithm.
 7. The system of claim 1, wherein thecentral command center processor is configured to correlate the data tothe database of fault signatures to identify the probable fault type. 8.The system of claim 7, wherein the central command center processor isconfigured to generate a fault warning, wherein the fault warningincludes the probable fault location and the probable fault type.
 9. Thesystem of claim 8, wherein the fault warning is at least one of a fax,an e-mail, a pager message, an audiovisual warning, a network alert, anSMS message, and a Simple Object Access Protocol (SOAP) message.
 10. Thesystem of claim 1, wherein the fault is an unbalanced power factor andthe central command center processor is configured to initiate one ormore predetermined power factor correction algorithms.
 11. The system ofclaim 1, wherein the fault is an electrical asset failure and thecentral command center processor is configured to initiate one or morepredetermined electrical asset isolation algorithms.
 12. The system ofclaim 1, wherein the fault is an electrical asset overload and thecentral command center processor is configured to initiate one or morepredetermined electrical asset bypass algorithms.
 13. The system ofclaim 1, wherein each monitor of the plurality of electrical assetmonitors further includes a GPS receiver for synchronizing the globallysynchronized timer and obtaining a plurality of coordinatescorresponding to a location of the monitor.
 14. A system for monitoringa plurality of electrical assets defining an electrical infrastructurefor pin pointing fault locations the system comprising: a plurality ofelectrical asset monitors coupled to respective ones of the electricalassets, each monitor including a sensor coupled to the electrical assetfor obtaining data corresponding to at least ones of a voltage, current,or a phase angle waveform, a globally synchronized timer to time stampthe data, to measure time and to provide position information, a meshnetwork radio, a power supply, and a power storage device; one or moregateways, each gateway including a gateway mesh network radio forcommunicating with the plurality of electrical asset monitors and anetwork interface for communicating with a central command center via anetwork distinct from the mesh network; the central command centerincluding a further network interface for communicating with the one ormore gateways, a memory for storing a database of fault signatures, asecond memory for storing the obtained data, a third memory for storingfixed asset information that includes at least one of cable type, cablepropagation velocity, cable segment length, or asset type and assetelectrical impedance, and a processor for analyzing the obtained data toidentify a probable fault type, a probable fault location, and a faultresponse; where a system is configured to calculate a fault locationfrom the globally synchronized times and at least one of respectivearrival times of the fault signal from multiple ones of the plurality ofelectrical asset monitors, asset monitor position, fault signalpropagation, and cable segment lengths.